Hydrogen sulfide treatment system

ABSTRACT

The present invention provides a system for treating a process fluid. The system includes a modular arrangement that includes ten modules for; reducing the amount of dissolved and entrained hydrogen sulfide gas in the process fluid; monitoring the pH of the process fluid; storing the process fluid; reducing an amount of oil from the process fluid; and flocculating the process fluid; measuring the amount of oil in the process fluid; providing ventilation supply air to at least one of the modules; removing hydrogen sulfide gas from a sour gas; delivering gases to a burner system; and controlling the processes of the system.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application, pursuant to 35 U.S.C. §119(e), claims priority to U.S.Provisional Application Ser. No. 60/776,331, filed on Feb. 24, 2006.That application is incorporated by reference in its entirety.

BACKGROUND OF INVENTION

1. Field of the Invention

The invention relates generally to a system for treating process fluids.

2. Background Art

When drilling or completing wells in earth formation, various fluidstypically are used in the well for a variety of reasons. As used herein,such fluids will be referred to as “process fluids.” Common uses forprocess fluids include: lubrication and cooling of drill bit cuttingsurfaces while drilling generally or drilling-in (i.e., drilling in atargeted petroleum bearing formation), transportation of “cuttings”(pieces of formation dislodged by the cutting action of the teeth on adrill bit) to the surface, controlling formation fluid pressure toprevent blowouts, maintaining well stability, suspending solids in thewell, minimizing fluid loss into and stabilizing the formation throughwhich the well is being drilled, fracturing the formation in thevicinity of the well, displacing the fluid within the well with anotherfluid, cleaning the well, testing the well, implacing a packer fluid,abandoning the well or preparing the well for abandonment, and otherwisetreating the well or the formation.

In drilling some subterranean formations, and particularly those bearingoil or gas, hydrogen sulfide accumulations are frequently encountered.The drilling fluid brings the hydrogen sulfide to the surface. Suchsulfide in the drilling fluid is problematic, as it can corrode thesteel in the drilling apparatus and may be liberated into the atmosphereas toxic sulfide gas at the well surface. Further, oil from the drillingfluid (as well as any oil from the formation) maybe become associatedwith or absorbed to the surfaces of the cuttings that are removed fromthe formation being drilled. The cuttings may then be an environmentallyhazardous material, making disposal a problem.

Generally, to protect the health of those working with the drillingfluid and those at the surface of the well, conditions should bemaintained to ensure that the concentration of hydrogen sulfide abovethe fluid, emitted due to the partial pressure of the gas, is less thanabout 15 ppm. The partial pressure of hydrogen sulfide at ambienttemperatures is a function of the concentration of sulfide ions in thefluid and the pH of the fluid. To ensure that the limit of 15 ppm is notexceeded even for the maximum sulfide concentration that may beencountered in a subterranean formation, the pH of the drilling fluid istypically maintained at a minimum of about 11.5. Also, to prevent thesoluble sulfide concentration in the fluid from becoming excessive,action is routinely taken to remove sulfide from the fluid.

Dissolved gases cause many problems in the oil field. Gases and otherfluids present in subterranean formations, collectively called reservoirfluids, are prone to enter a wellbore drilled through the formation. Inmany cases, dense drilling fluids, completion brines, fracturing fluids,and so forth are provided to maintain a countering pressure thatrestrains the reservoir fluids from entering the wellbore. However,there are many instances where the counter pressure is too low torestrain the reservoir fluids. This may be due to, for example, amis-calculation of the fluid density needed to maintain a hydrostaticoverbalance or a transient lowering of pressure due to movement of thedrill string in the hole. Gasses may also enter the wellbore throughmolecular diffusion if there is insufficient flux of fluid from thewellbore to keep it swept away. Finally, reservoir fluids escape fromthe fragments of the formation that are being drilled up. The reservoirfluid that enters the well is then free to mix with the supplied wellfluid and rise to the surface.

The hazards of un-restrained expansions of reservoir fluids in thewellbore are well known. A primary hazard is an avalanche effect of gasevolution and expansion, wherein gas bubbles rise in a liquid stream,expanding as they rise. As the bubbles expand, they expel dense fluidfrom the bore, and further reduce the hydrostatic pressure of thewellbore fluid. Such a progression may eventually lead to a ‘blow out,’whereby so much restraining pressure has been lost that the highpressure reservoir can flow uncontrollably into the wellbore.

Less dramatic, but equally important, are chemical effects thatformation fluids may have upon the circulating fluid, the structure ofthe well, and the associated personnel. These effects and risks mayinclude, for example: methane gas liberated at the surface may ignite;carbon dioxide may become carbonic acid, a highly corrosive compound,when exposed to water; carbon dioxide gas is an asphyxiant; hydrogensulfide can corrode ferrous metals, particularly in contact with water,and is more damaging than carbon dioxide because it can induce hydrogenembrittlement; embrittled tubulars may separate or break well underdesign stresses with catastrophic consequences; hydrogen sulfide gas isalso toxic, with levels of 800 to 1000 ppm causing death in healthyindividuals. Removing dissolved and entrained gases is thus vital tomany aspects of successful drilling and exploitation.

Process fluids from wells are typically sent offsite for treatment andprocessing to remove hazardous materials from the process fluid. Forexample, gases, such as hydrogen sulfide, solids, for example amounts ofearth formation, cuttings, debris, etc., and other fluids, for exampleoil, may be removed from the process fluid during such processing of theprocess fluid so that the process fluid may be safely disposed orre-circulated to the well. Sending process fluids offsite may becumbersome and costly due to the potential risks involved, includinghealth risks for personnel handling the transport of the process fluidsand environmental risks of leakage or spillage of the process fluidduring transportation.

Accordingly, there exists a need for a system and method for treating aprocess fluid, including facilitating the reduction of entrained anddissolved gases in the process fluid.

SUMMARY OF INVENTION

In one aspect, the invention relates to a system for treating a processfluid comprising a modular arrangement, the modular arrangementincluding a first module that reduces the amount of dissolved andentrained hydrogen sulfide gas in the process fluid and monitors the pHof the process fluid, a second module in fluid communication with thefirst module that stores the process fluid if an amount of hydrogensulfide gas entrained in the process fluid is above a pre-selectedvalue, a third module in fluid communication with the second module thatreduces an amount of oil from the process fluid and flocculates theprocess fluid, a fourth module in fluid communication with the thirdmodule that reduces the amount of solids from the process fluid, a fifthmodule in fluid communication with the fourth module that measures theamount of oil in the process fluid and stores treated process fluid, asixth module in fluid communication with at least one of the firstmodule, the second module, the third module, and the fourth module thatprovides ventilation supply air, a seventh module in fluid communicationwith the first module and the second module that removes hydrogensulfide gas from a sour gas, an eighth module in fluid communicationwith the seventh module that delivers gases to a burner system, a ninthmodule in communication with the first through eighth modules of thesystem that controls the processes of the system, and a tenth module incommunication with the local electric room module having a work stationand a system laboratory.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a modular system in accordance with an embodiment of theinvention.

FIG. 2 shows a primary separation module in accordance with anembodiment of the invention.

FIG. 3 shows a degassing and neutralizing module in accordance with anembodiment of the invention.

FIG. 4 shows a process fluid storage module in accordance with anembodiment of the invention.

FIG. 5 shows an oil removal and flocculation module in accordance withan embodiment of the invention.

FIG. 6 shows a solids removal and filtration module in accordance withan embodiment of the invention.

FIG. 7 shows a treated fluid storage module in accordance with anembodiment of the invention.

FIG. 8 shows a local electric room module in accordance with anembodiment of the invention.

FIG. 9 shows a control room module in accordance with an embodiment ofthe invention.

FIG. 10 shows a sulfide treatment module in accordance with anembodiment of the invention.

FIG. 11 shows a burner line module in accordance with an embodiment ofthe invention.

FIG. 12 shows a ventilation supply module in accordance with anembodiment of the invention.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein are directed to a system andmethod for treating process fluids. In another aspect, embodimentsdisclosed herein are directed to a system and method for removinghydrogen sulfide from process fluids.

As used herein, ‘modular system’ refers to a grouping of units ormodules that are mobile, that may be of a standardized shape and/orsize, and that may be interconnected to form a larger system. As usedherein, a ‘process fluid’ refers to any fluid used in drilling orcompleting a well, including muds, brine, pills, water, etc. As usedherein, a ‘pill’ refers to any relatively small quantity of a blend ofdrilling fluid that is used to accomplish any specific task that aregular drilling fluid may not accomplish, for example lifting cuttingsfrom the wellbore, dissolve encroaching salt formations, destroy filtercakes, etc. As used herein, ‘client’ refers to any person, persons, orcompany that requested the treatment of a process fluid. For example,the client may be an oil company that requested the treatment of processfluid from one or more of its drilling sites. As used herein,‘flocculate,’ or ‘flocculation,’ means to cause to aggregate to formfloes or masses of fine suspended particles. As used herein, a ‘hopper’may be defined as a device used to facilitate the addition of processfluid additives or chemicals to a process fluid, wherein the processfluid enters the hopper and mixes with the additives.

Select embodiments disclosed herein include a modular system fortreating process fluid on-site. In one embodiment, the system includesmultiple mobile modules that may be transported and assembled on-site.In select embodiments, the system receives process fluids used duringdrilling and processes, or treats, them for disposal. In one embodiment,the system treats process fluids comprising a mixture of water, oil,hydrogen sulfide, brine, dead acid, and a small amount of solids.

Embodiments of the present invention involve a series of interconnectedmodules comprising a plurality of apparatuses for performing a pluralityof processes. Embodiments of the present invention provide a system ofmobile, connectable modules for processing or treating a process fluid.Each module is sufficiently small to be mobile and sufficiently large tocomprise process equipment, including tanks, valves, pumps, piping, etc.In one embodiment, any of the various modules may be assembled on-siteby fitting and/or connecting ladders, guardrails, pipework, electriccabling, and ventilation. Exemplary apparatuses and processes aredescribed below.

Process Overview

After drilling and completion of a well, the process fluids may containvarious amounts of entrained gases, oils, and solids. During clean up ofa well, process fluids may be treated by flowing the process fluidthrough a separator and surge tanks. Depending on the water and solidscontent, oil may be delivered to a burner, or returned to the separator.Gases removed from the process fluid in the separator may be sent to aburner. Fluids used during the clean up phase of a well include volumesof fluids from the tubing volume or brine, pills, and water used to washequipment at the end of a test or stimulation program. Process fluidsused during drilling and completion of a well may contain variousamounts of hydrogen sulfide gas that may vary from a few parts permillion (ppm) to over 10,000 ppm.

After stimulation of the well, additives, such as acid and chemicalmixtures, associated with the drilling process are flowed back orreturned to the surface. These additives may include surfactants,corrosion inhibitors, iron control agents, and solvents. Theeffectiveness of the acid and the chemicals during the drilling processdepends on the well conditions and the estimated area of the reservoirformation. Part of the acid and other fluid components may not becompletely consumed when returned to the surface and must be neutralizedfor safe disposal.

In one embodiment, a system for treating process fluid, includingremoval of hydrogen sulfide, is shown in FIG. 1. Process fluid enters 24the modular system for treating 22 a process fluid wherein the processfluid is processed and treated for safe disposal of the process fluid.In one embodiment, the modular system 22 comprises a plurality ofmodules, wherein the size of each module is sufficiently small to bemobile. Accordingly, the modules may be assembled on-site. In oneembodiment, the modules have approximate dimensions of about 20 ft inlength and 8 ft in width. One of ordinary skill in the art, however,will appreciate that any size module that is sufficiently small to bemobile and sufficiently large to house tanks, pumps, and processequipment may be used without departing from the scope of the invention.In one embodiment, the modular system 22 may be configured to treatprocess fluids that comprise a mixture of water, oil, hydrogen sulfide,brine, dead acid, and solids.

In one embodiment, a process fluid enters 24 the modular system 22 andfirst enters a primary separation module 101. The primary separationmodule 101 may be used for coil tubing drilling application andgenerally not during normal operation with acid flow backs. The primaryseparation module 101 may remove gas and solids from the process fluid.Additionally, the primary separation module 101 may provide an interfacebetween high pressure and low pressure operation, in the event equipmentupstream from the system 22 fail to limit high pressure to the system22. After the process fluid flows through the primary separation module101, thereby removing entrained gas and solids, the process fluid may bepumped to the degassing and neutralizing module 211. In an alternateembodiment, process fluid may enter 24 the modular system 22 from aclient and enter the degas sing and neutralizing module 211, withoutfirst entering the primary separation module 101.

In this embodiment, a degassing and neutralizing module 211 comprises atank having a degassing compartment (213 in FIG. 3) that reduces theamount of dissolved and entrained hydrogen sulfide gas from the processfluid and a neutralizing compartment (214 in FIG. 3) that monitors andadjusts the pH of the process fluid. The process fluid may then bepumped to the process fluid storage module 331.

In this embodiment, a process fluid storage module 331 comprises astorage tank (332 in FIG. 4). Process fluid from the degassing andneutralizing module (221) having more than a pre-selected value ofhydrogen sulfide is flowed into the storage tank (332 in FIG. 4) in theprocess fluid storage module 331. Process fluid stored in the processfluid storage module may then be returned to the degassing andneutralizing module 211 for further processing. If the process fluidfrom the degassing and neutralizing module (221) has less thanpre-selected value of hydrogen sulfide, then the process fluid is sent26 from the process fluid storage module 331 through a piping suitcase28 to the oil removal and flocculation module 441.

In this embodiment, an oil removal and flocculation module 441 comprisesa coalescing tank (442 in FIG. 5) for the removal of oil from a processfluid and a flocculation tank (451 in FIG. 5) for process fluidflocculation. Recovered oil from the coalescing tank may be sent to anIBC for storage or piped directly to the client. After the process fluidflows through the coalescing tank and the flocculation tank, the processfluid may be transferred to the solids removal and filtration module551.

In this embodiment, a solids removal and filtration module 551 comprisesa belt filter (553 in FIG. 6 for removing solid material from a processfluid coupled to a storage tank (554 in FIG. 6). In one embodiment, atleast one filter canister may be coupled to the storage tank 554.Process fluid from the solids removal and filtration module 551 may thenbe pumped through the piping suitcase 28 to the treated fluid storagemodule 661, as indicated by the process flow arrows 30.

In this embodiment, a treated fluid storage module 661 comprises anoil-in-water monitoring system (663 in FIG. 7) for measuring theconcentration of oil within a treated process fluid entering the treatedfluid storage module 661 from the solids removal and filtration module551 and a tank (664 in FIG. 7) for storing the treated process fluid.The process fluid stored in the treated fluid storage module 661 may besent 32 to the client as treated process fluid. Additionally, theprocess fluid stored in the treated fluid storage module 661 may bere-circulated 34 to the degassing and neutralizing module 211 for tankcleaning or reprocessing, or sent to the oil removal and flocculationmodule 441 for further processing.

In this embodiment, a local electric room module 771 is electricallyconnected to each of the various modules, as indicated by the dashedlines 40 and 41. In this embodiment, the local electric room comprises ahydrogen sulfide PLC system 773, a F&G/ESD system 774, and a MCC 775(FIG. 8). The local electric room module 771 houses the system andequipment responsible for controlling the intermodular processes and theprocesses within each module. The hydrogen sulfide PLC system maycontrol the system process, the F&G/ESD system may control the processfor shutting down the system safely should a serious process conditionoccur, and the MCC controls the motor power for the system.

In this embodiment, a control room module 881 is electrically connected43 to at least one of they systems, including the hydrogen sulfide PLCsystem 773, the F&G/ESD system 774, and the MCC 775 (FIG. 8), disposedin the local electric room module 771. The control room module 881 maybe disposed on top of the local electric room module 771 and maycomprise an operator work station and a system laboratory. The controlroom module 881 may comprise a hydrogen sulfide PLC HMI and a hydrogensulfide PLC server, thereby providing an operator with a graphicalinterface of the processes of the modular system 22. In one embodiment,the graphical interface may display the modular system 22, in P&IDformat.

In this embodiment, a sulfide treatment module 991 comprises a tank 994that contains a consumable medium that chemically reacts with a sour gasstream that enters the sulfide treatment module 991 from the mechanicaldegasser 220 (FIG. 3) in the degassing and neutralizing module 211, asindicated by process flow arrow 36, the degassing compartment 213 of thedegassing and neutralizing module 211, as indicated by process flowarrow 38, the neutralizing compartment 214 of the degassing andneutralizing module 211, as indicated by process flow arrow 39, and/orthe process fluid storage module 331 to convert hydrogen sulfide into asafe material for disposal. The processed gas stream may then beextracted and sent to the burner line module 1020.

In this embodiment, a burner line module 1020 extracts gases from thesulfide treatment module 991 and delivers the gases to the a burnersystem. In one embodiment, the burner system may comprise at least oneburner 1030. The burner line module comprises a hydrogen sulfide gasdetection system 1025, a particulate filter 1022, a detonation arrestor1024, a rupture disc 1026, and a centrifugal blower 1028 (FIG. 11).

In this embodiment, a ventilation supply module 1110 suppliesventilation air to at least one of the modules of the modular system 22.The ventilation supply air may be ducted from an elevation ofapproximately 10 ft above the control room module 881. In oneembodiment, the ventilation supply module 1110 may be disposed on top ofthe solids removal and filtration module 551. The ventilation supplymodule 1110 may comprise isolation dampeners 1124, an air heater 1112, acoalescing filter 1114, and an axial blower 1116 (FIG. 12). Theventilation supply module 1110 passes supply air through a heater and acoalescing filter and then separates into two supply systems. A firstsystem 1120 may supply air by insulated ducting to the degassing andneutralizing module 211 and process fluid storage module 331. A secondsystem 1122 may duct supply air to the oil removal and flocculationmodule 441 and the solids removal and filtration module 551.

In this embodiment, a piping suitcase 28 allows easy connection ofpiping for the system and for module interconnections. In oneembodiment, the piping suitcase 28 may include a plurality of pipes,connections, and inline process equipment that allows a module to becoupled to another module by coupling each module to the piping suitcase28.

Equipment that may not exposed to corrosive fluids, including, forexample, tanks, inline process equipment, piping, flanges, etc., may beconstructed of carbon steel with the surfaces prepared and coated.

Structural equipment, for example lifting frames, may be constructed oflow temperature carbon steel, surface prepared and coated. Bulkheads maybe constructed of carbon steel, surface prepared and coated. Fire ratedbulkhead insulation material may be A-60 fire rated. Non-fire ratedbulkhead insulation material may be fire and moisture resistant.

Primary Separation Module

FIG. 2 shows a primary separation module 101, as may be optionally usedin one embodiment to reduce the amount of gas and solids entrained in aprocess fluid. For example, in one application, the primary separationmodule 101 may be used for coil tubing drilling applications. In anotherexample, a primary separation module 101 is not used during normaloperation with acid flow backs. In present in the process, the primaryseparation module 101 comprises a tank 102 for storing a process fluid.In one embodiment, the tank 102 may be a cyclone separator. The primaryseparation module 101 may further comprise separation baffles 103disposed inside the tank 102 over which the process fluid flows, therebyreleasing entrained gases in the process fluid. A pump 104, for examplea diaphragm pump, may be coupled to the tank 102 to inject a hydrogensulfide scavenger material into the process fluid to remove entrainedhydrogen sulfide. For example, copper, zinc, or iron compounds may beadded to the process fluid to react with and sequester hydrogen sulfide.One of ordinary skill in the art will appreciate that there are numerousscavenger materials known in the art that may be used to react with andsequester entrained hydrogen sulfide. A blower may be coupled to thetank to extract gases, for example, to extract hydrogen sulfide,released from the process fluid during the primary separation. Actuatedvalves may be coupled to the blower and the tank 102 to regulate the gasthat is removed from the primary separation module 101 and to regulatereplacement air flowed into the tank 102. Additionally, a weirarrangement 105 configured to separate solids from the process fluid maybe disposed inside the tank 102. A transfer pump 106 may be coupled tothe tank 102 to transfer the process fluid treated in the primaryseparation module 101 to another module, such as the degassing andneutralizing module 211 (described in more detail below with referenceto FIG. 3). In one embodiment, the transfer pump 106 may be acentrifugal pump. A system of valves 111, 112, 113, and 114 may becoupled to the tank 102 to control the flow of the process fluid andchemicals. In one embodiment, the primary separation module 101 may beventilated by at least one louver 107, that may be fixed or variable.

In one embodiment, as shown in FIG. 2, process fluid from the well or aclient 90 enters tank 102. The shape of the tank 102 and the movement ofthe fluid inside the tank 102 provide a hydro cyclonic effect on theprocess fluid to facilitate separating entrained gases from the processfluid. Additionally, gas may be separated from the process fluid as theprocess fluid strikes the inside wall of the process tank 102 and as theprocess fluid flows over the separation baffles 103 disposed inside thetank 102. Hydrogen sulfide scavenger material may be injected into theprocess fluid in the tank through a diaphragm pump 104 to react with andsequester the hydrogen sulfide. Additionally, compressed air 108 may beinjected into the process fluid in the tank 102 to cause an additionalamount of entrained hydrogen sulfide to be released from the processfluid. In one embodiment, reactions between the scavenger material andhydrogen sulfide and/or compressed air and hydrogen sulfide may resultin elemental sulfur. The elemental sulfur may then settle to the bottomof the tank 102. Additionally, entrained hydrogen sulfide released fromthe process fluid may be extracted from the tank 102 by a blower 115 andtransferred to a sulfide treatment module 991 (FIG. 10).

In one embodiment, the process fluid flows (indicated at A) through aweir arrangement 105 in tank 102. The weir arrangement 105 separatessolid materials from the process fluid. The solid materials separated bythe weir arrangement may settle to the bottom of the tank 102. Theprocess fluid may then flow over the weir arrangement and exit the tankat an outlet 109. The process fluid may then be exported by a transferpump 106 to a degassing and neutralizing module 211 for furtherprocessing.

Degassing & Neutralizing Module

One embodiment of a degassing and neutralizing module 211 is shown inFIG. 3. The degassing and neutralizing module 211 is configured toreduce the amount of dissolved and entrained gases from a process fluid.In one embodiment, the process fluid entering the degassing andneutralizing module may be process fluid from another module, forexample, the primary separation module 101. The degassing andneutralizing module 211 comprises a tank 212 having a first compartmentand a second compartment separated by a weir arrangement 215. In oneembodiment, a first compartment, or degassing compartment 213, reducesthe amount of dissolved and entrained hydrogen sulfide gas in theprocess fluid and a second compartment, or neutralizing compartment 214,adjusts the pH of the process fluid. In one embodiment, the degassingand neutralizing module 211 may be coupled to a ventilation supplymodule 1110 (described in more detail below with reference to FIG. 12)for ventilation of the degassing and neutralizing module 211. While thedegassing and neutralizing processes described herein are disposed inone module, the degassing and neutralizing module 211, one of ordinaryskill in the art will appreciate that these two processes may bedisposed in separate modules, so long as each module is sufficientlysmall to be mobile and each module may be connected to another modulefor assembly on-site.

In one embodiment of a method for using a system having a degassing andneutralizing module 211, the degassing and neutralizing module 211 ispurged prior to operating the degassing and neutralizing module 211. Forexample, the degassing and neutralizing module 211 may be purged for afew minutes, such as approximately ten minutes, prior to operation.Ventilation air may be supplied to the degassing and neutralizing modulefrom a ventilation supply module 1110. In one embodiment, ventilationair is flowed through the degassing and neutralizing module 211. Theventilation air flow may be regulated so that up to twelve air changesor more are performed per hour within the degassing and neutralizingmodule 211. Additionally, the ventilation air may be extracted at ahigher rate than the supply rate to maintain a negative module pressurethat reduces the risks of leakage to the outside. In one embodiment, theventilation air may be extracted at 20 percent above its supply rate. Insome embodiments, the degassing compartment 213 and the neutralizingcompartment 214 may be ventilated at up to 30 air changes or more perhour. In one embodiment, the air is changed often enough so that theair/gas ratio is maintained below the Lower Explosive Limit (LEL). Theventilated air from the degassing compartment 213 and the neutralizingcompartment 214 may be extracted by blower 240 and air from themechanical degasser may be extracted by blower 241. The extracted airmay be vented to another module, for example, a sulfide treatment module991 (as described in more detail below with reference to FIG. 10),wherein hydrogen sulfide may be removed from the extracted gas. In theevent of an Emergency Shut Down (ESD), isolation dampeners 242 mayclose, thereby preventing ventilation air from entering or exiting thedegassing and neutralizing module 211.

Degassing. Compartment

In one embodiment, process fluid is flowed at 243 from any of a numberof possible sources, for example, the primary separation module 101, atreated fluid storage module 661 (described in more detail below withreference to FIG. 7), and/or a process fluid storage module 331(described in more detail below with reference to FIG. 3), into adegassing compartment 213, wherein the amount of entrained and dissolvedgases, such as hydrogen sulfide, in the process fluid may be reduced. Inone embodiment, the degassing compartment 213 comprises a pH analyzer218 a that monitors the pH of the process fluid in the degassingcompartment 213. The degassing compartment 213 further comprises amechanical degasser 220. The process fluid passes through the mechanicaldegasser wherein centrifugal force is exerted on the well fluid. Thecentrifugal force of the mechanical degasser multiplies the force actingon the entrained gas bubbles, for example, hydrogen sulfide, to increasebuoyancy of the gas bubbles, thereby releasing an amount of entrainedgas bubbles from the well fluid. The increase in buoyancy of the gasbubbles accelerates the bubble-rise velocity. As the bubbles rise towardthe surface, they escape the process fluid. One of ordinary skill in theart will appreciate that any device known in the art that will exert acentrifugal force on the fluid, thereby reducing the amount of entrainedor dissolved gases in the process fluid may be used in place of amechanical degasser. The degassing compartment 213 may further includemeans 221 for aerating the process fluid to enhance the removal ofentrained gas bubbles. One example of a degassing compartment 212 withmeans 221 for aerating the process fluid that may be used in accordancewith embodiments of the present invention is described in a co-pending,co-owned U.S. Patent Application Ser. No. 60/776,372 titled “AeratedDegasser,” filed simultaneously with the present application which isincorporated by reference herein, in its entirety.

In one embodiment, a process fluid enters a degassing and neutralizingmodule 211, first entering a degassing compartment 213. The processfluid pours into the degassing compartment 213 until it reaches apre-selected depth corresponding to a pre-selected volume. For example,in one embodiment, the pre-selected depth corresponds to a volume ofapproximately two hundred cubic feet (about 6 m³) of process fluid. A pHanalyzer 218 a monitors the pH of the process fluid. The pH of theprocess fluid may be measured by any method known in the art, and is notlimited herein. If the process fluid has a pH greater than 4, then acidmay be added, shown at 222, to the process fluid until a pH of less than4 is reached. In one embodiment, the pH of the process fluid ismaintained between 3.0 and 3.5. In one embodiment, the acid added to theprocess fluid to maintain the pH may be citric acid. One of ordinaryskill in the art will appreciate that other acids may be used to lowerand maintain the pH of the well fluid.

One commercially available degasser that may be useful in thisapplication is a MI SWACO® CD-1400, available from M-I, LLC (Houston,Tex.). The mechanical degasser 220 may be coupled to the degassingcompartment 213. Process fluid passes through the mechanical degasser220 wherein a centrifugal force is exerted on the process fluid tofacilitate removal of entrained gases from the process fluid. Themechanical degasser 220 may be controlled by a programmable logiccontroller (PLC) 223 a that activates the mechanical degasser 220 oncethe level of process fluid in the degassing compartment 213 reaches apredetermined level for safe operation of the mechanical degasser 220. Ablower 240, 224 may be coupled to the mechanical degasser 220 to extractgas removed from the process fluid. In one embodiment, entrained gasesmay removed and sent to a sulfide treatment module 991 or to a flare 225for burning.

In one embodiment, an aeration device 221 may be disposed in thedegassing compartment 213 that injects or sparges compressed air intothe process fluid. The compressed air may react with dissolved orentrained hydrogen sulfide in the process fluid thereby producingelemental sulfur. Elemental sulfur may then be more easily separatedfrom the process fluid. One example of sparging a process fluid withcompressed air that may be used, in accordance with embodiments of thepresent invention, is described in U.S. Patent Application Ser. No.60/776,372 titled “Aerated Degasser,” filed simultaneously with thepresent application which has been incorporated by reference herein, inits entirety. In one embodiment, the aeration device 221 may comprise aseptum or membrane having small perforations through which air issparged. The membrane may be flexible, such as a woven or non-wovenfabric, or a sheet of rubber or other elastomer with perforated openingscast or otherwise formed therethrough. Alternatively, the membrane maybe rigid, for example a solid frit, which is a body of sinteredparticles with fine openings between particles, or a metal surface withfine perforations, or openings devised by any means known in the art.One of ordinary skill in the art will appreciate, however, that themembrane may be constructed of any of a number of materials known in theart that resist deterioration in the process fluid and formed such thatair may be sparged through the membrane and into the fluid.

In one embodiment, the aeration device may be disposed proximate theintake 226 of the mechanical degasser 220. The mechanical degasser maybe run simultaneously with the aeration device. In this embodiment, thecentrifugal force of the mechanical degasser 220 multiplies the forceacting on the entrained gas bubbles and air bubbles to increase buoyancyand release of both the entrained gas bubbles and the air bubbles. Theincrease in buoyancy of the bubbles accelerates the bubble-risevelocity. As the entrained gas bubbles and the oxygen bubbles risetoward the surface, they escape the well fluid. As the process fluidlevel in the degassing compartment 213 rises above a pre-selected depthof contained process fluid due to the input flow of process fluid intothe degassing compartment 213 and the sparged air, the contained processfluid flows, as shown at B, through a weir arrangement 215 in thedegassing and neutralizing module 211 into the neutralizing compartment214.

Neutralizing Compartment

In one embodiment, process fluid from the degassing compartment 213flows into a neutralizing compartment 214, wherein the process fluid issampled and tested for the presence of hydrogen sulfide. In oneembodiment, the neutralizing compartment 214 comprises a pH analyzer 218b for measuring the pH of the process fluid. In this embodiment, theneutralizing compartment 214 further comprises at least one pump 227,for example a diaphragm pump, that may supply chemicals for adjustingthe pH of the process fluid. Additionally, the neutralizing compartment214 comprises fluid samplers 247 that extract samplings of the processfluid for testing. In this embodiment, the neutralizing compartment 214further comprises a dissolved sulfide analyzer or monitor 246. In oneembodiment, a dissolved sulfide monitor 246 may be used to measure thesulfides in solution in the process fluid. In this embodiment, thesulfides in the process fluid may be monitored continuously with minimalmaintenance and adjustment. Those having ordinary skill in the art willappreciate that monitoring may also occur on a non-continuous basis.Variable speed driven pumps 245 and static mixers 228 coupled to theneutralizing compartment 214 inject hydrogen scavenger material into theprocess fluid. The neutralizing compartment 214 further comprises atransfer pump 230 for transferring process fluid to another module, suchas a process fluid storage module 331 (described in more detail belowwith reference to FIG. 4).

In one embodiment, process fluid flows, shown at B, over the weirarrangement 215 from a degassing compartment 213 to a neutralizingcompartment 214. In this embodiment, the pH of the process fluid ismeasured and monitored by a pH analyzer 218 b controlled by a hydrogensulfide PLC 223 b. The pH of the process fluid may be adjusted to apredetermined pH value. In one embodiment, the predetermined pH valuemay be a minimum of 6. Chemicals may be added to the process fluid viapumps 227 to adjust the pH of the process fluid. In one embodiment, forexample, a basic material such as caustic soda, may be added to theprocess fluid to raise the pH of the process fluid. Alternatively, anacidic material, such as citric acid, may be used to lower the pH of theprocess fluid in the neutralizing compartment 214.

In one embodiment, fluid samplers 247 may be coupled to the neutralizingcompartment 214 for extracting samples of process fluid. For example, afluid sampler sold under the trademark Jiskoot 210P available fromJiskoot, London, England may be used. One of ordinary skill in the artwill recognize that any sampler may be used such that the samplerextracts accurate sampling of fluid from the process fluid for testing.Multiple samples may be collected and tested for hydrogen sulfide. Inone embodiment, four samples are extracted and tested. Each sample maybe automatically fed into a dissolved sulfide monitor 246, for example,an ATI Model A15/81 dissolved sulfide monitor available from AnalyticalTechnology, Inc., Collegeville, Pa., and mixed with an acid. In oneembodiment, the sample is mixed with sulfuric acid. Within the dissolvedsulfide monitor 246, the sample and acid mixture flow into a chamberwherein hydrogen sulfide is stripped from the sample. A sensor disposedin the dissolved sulfide monitor 246 is located in a gas stream of thesample and measures a release of hydrogen sulfide concentration. In thedissolved sulfide monitor 246 of this embodiment, the sensor does notcome into contact with the sample, but rather the gas stream thatcontains the stripped hydrogen sulfide contacts the sensor. The sensorsends the measurement results to a hydrogen sulfide PLC 223 c.

During the sampling process, hydrogen sulfide scavenger material may beinjected into the process fluid. In one embodiment hydrogen sulfidescavenger material may be injected by the variable speed driven pump 245and the static mixer 228, which results in a two stage process ofscavenging hydrogen sulfide. In this embodiment, as less hydrogensulfide is detected by the dissolved sulfide monitor 246, the variablespeed driven pump 245 reduces the flow of hydrogen sulfide scavengermaterial. The speed of the variable speed driven pump 245, and therebythe rate at which scavenger material is injected into the process fluid,may be controlled by the hydrogen sulfide PLC 223 c.

Once the hydrogen sulfide concentration of the process fluid has reacheda predetermined concentration, the process fluid may be transferred orflowed to another module, for example, a process fluid storage module331 or an oil removal and flocculation module 441 (both described infurther detail below with reference to FIGS. 4 and 5, respectively). Inone embodiment, a transfer pump 230, for example, a low shear rotarypump, may be coupled to the neutralizing compartment 214 and maytransfer the process fluid to the process fluid storage module 331. Inthis embodiment, the hydrogen sulfide PLC 342 (FIG. 4) may control orregulate the pump operation. In one embodiment, a valve arrangement 232may be coupled to piping between the neutralizing compartment 214 andthe process fluid storage module 331 that diverts process fluid back at233 to the neutralizing compartment 214 to regulate the flow of processfluid to the process fluid storage module 331 and further downstream. Inone embodiment, the process fluid flow between the neutralizing module214 and the process fluid storage module 331 may be maintained at a rateof about 210 gpm. In one embodiment, the transfer pump 230 may becoupled with the degassing compartment 213 of the degassing andneutralizing module 211 to remove the process fluid from the degassingcompartment 213.

Process Fluid Storage Module

FIG. 4 shows one embodiment of a process fluid storage module 331. Inthe embodiment shown, the process fluid storage module 331 comprises aprocess fluid storage tank 332 configured to store process fluid. In oneembodiment process fluid from a previous module, such as from thedegassing and neutralizing module 211, with a measured hydrogen sulfidecontent above a predetermined value may be stored in the process fluidstorage module 331. In this embodiment, the process fluid stored in theprocess fluid storage module 331 may then be returned to a previousmodule, such as the degassing and neutralizing module 211, forre-treatment. In one embodiment, a transfer pump 336, 340 coupled to theprocess fluid storage module 331 may transfer stored process fluid toanother module for example, a degassing and neutralizing module 211 oran oil removal and flocculation module 441. A sensor 338 disposed in theprocess fluid storage tank 332 monitors the level of process fluidcontained in the process fluid storage module 331. The process fluidstorage module 331 further comprises an air receiver 337 that receivesair from the ventilation module 1110 (see FIG. 12) and maintainssufficient volumes of air for performing the system operation.

In one embodiment, a transfer pump 340, for example, a low shear rotarypump, transfers process fluid with a hydrogen sulfide content below apre-selected value from the degassing and neutralizing module 211 (FIG.3) to another module, for example, an oil removal and flocculationmodule 441 (as described in more detail below with reference to FIG. 5)for further treatment. Alternatively, the transfer pump may transferprocess fluid with a hydrogen sulfide content below a pre-selected valuefrom the degassing and neutralizing module 211 to the process fluidstorage tank 332 for storage. In one embodiment, the pre-selected valuemay be about 5 ppm. One of ordinary skill in the art will appreciatethat the pre-selected value may be selected by a client, environmentalregulations, or requirements of the system. In one embodiment, theprocess fluid storage tank 332 may have a volume of approximately fivehundred cubit feet (about 15 m³). The transfer of fluids from thedegassing and neutralizing module 211 to the process fluid storagemodule 331 or an oil removal and flocculation module 441 may becontrolled by a hydrogen sulfide PLC 342. The process fluid stored inthe process fluid storage module 331 may then be returned by a transferpump 336 to the degassing and neutralizing module 211 for re-treatment,thereby reducing the concentration of hydrogen sulfide in the processfluid. The transfer pump 336 for returning process fluid from theprocess fluid storage module 331 to the degassing and neutralizingmodule 211 may be, for example, a low shear rotary pump.

The process fluid storage module 331 may be ventilated by purging theair within the module prior to operation (such as ten minutes prior). Inone embodiment, ventilation air may be supplied to the process fluidstorage module 331 from the ventilation module 1110 at a rate of up totwelve air changes or more per hour. In one embodiment, ventilation airmay be extracted from the process fluid storage module 331 up to 20percent or more above the supply rate. The process fluid storage tank332 may be ventilated up to 20 times per hour or more. The ventilatedair may be extracted by a blower 344 and vented through another module,for example, a sulfide treatment module 991, wherein hydrogen sulfidemay be removed from the extracted gas. In the event of an Emergency ShutDown (ESD), isolation dampeners 346 may close, thereby preventingventilation air from entering or exiting the process fluid storagemodule 331.

Oil Removal & Flocculation

FIG. 5 shows one embodiment of an oil removal and flocculation module441. In the embodiment shown, the oil removal and flocculation module441 comprises a coalescing tank 442 for the removal of oil from aprocess fluid and a flocculation tank 451 for process fluidflocculation. In one embodiment, the process fluid may be process fluidfrom a previous module, for example the process fluid storage module 331or the degassing and neutralizing module 211. In one embodiment, thecoalescing tank 442 may comprise at least one level sensor 456 thatmeasures the level or volume of process fluid in the coalescing tank442. Additionally, the coalescing tank 442 may further comprise a pumpfor adding emulsion breakers to the process fluid and at least onefilter for reducing oil in the process fluid. In this embodiment, a pump445 may transfer the process fluid from the coalescing tank 442 througha hopper 447 and into the flocculation tank 451. In one embodiment,flocculating chemicals may be added to the process fluid in the hopper447. In one embodiment, a transfer pump 453 may be coupled with theflocculation tank 451 for transferring process fluid to another module,for example the solids removal and filtration module 551. While the oilremoval and flocculation processes described herein are disposed in onemodule, the oil removal and flocculation module 441, one of ordinaryskill in the art will appreciate that these two processes may bedisposed in separate modules, for example, the coalescing tank 442 maybe disposed in one module, the flocculation tank in a second module, andthe hopper in a third module, so long as each module is sufficientlysmall to be mobile and each module may be connected to another modulefor assembly on-site.

In one embodiment, process fluid from another module, for example, thedegassing and neutralizing module 211 or the process fluid storagemodule 331, may be transferred via a pump 453, for example, a low shearrotary pump, into an oil removal and flocculation module 551. In thisembodiment, the process fluid enters a first compartment 444 of acoalescing tank 442 having three compartments. A level sensor 456coupled to the coalescing tank 442 measures the level of process fluidcontained in the coalescing tank 442. The level sensor 456 may becoupled to a hydrogen sulfide PLC 457 to control the pump operation 340(FIG. 4) in accordance with the measured process fluid level in thecoalescing tank 442. In one embodiment, the level sensor 456 may be awire rope sensor disposed inside the first compartment 444 of thecoalescing tank 442. In one embodiment, the coalescing tank 442 may havea volume of approximately two hundred cubic feet (about 6 m³). Emulsionbreakers 469 may be added to the process fluid by a pump 466 coupled tothe coalescing tank 442 to facilitate oil removal from the processfluid. The process fluid may then flow over a coalescing filter 460 anda coalescing oil trap 461 that remove oil entrained in the process fluidand into a second compartment 463 of the coalescing tank 442. Theprocess fluid in the second compartment 463 may then flow through a weirarrangement 465 into a third compartment 467 of the coalescing tank 442.Oil recovered from process fluid in the coalescing tank 442 may betransferred to an intermediate bulk container (IBC) for storage or pipeddirectly to a client.

In one embodiment, process fluid from the coalescing tank 442 is pumpedthrough a hopper 447 by a pump 445, for example, a centrifugal pump 445,and into the flocculation tank 451. In one embodiment, the flocculationtank 451 may be approximately one hundred forty cubic feet (about 4 m³).As the process fluid is pumped through the hopper 447, flocculatingchemicals, for example, bentonite, may be added and mixed with theprocess fluid. In one embodiment, the flocculating chemicals may beadded manually. One of ordinary skill in the art will appreciate,however, that other methods of adding flocculating chemicals to thehopper 447 may be used without departing from the scope of theinvention. The process fluid may then flow into the flocculation tank451, wherein suspended particles in the process fluid aggregate, forminga floc or a mass of fine suspended particles. A mixer 448 or agitatormay be disposed in the flocculating tank 451. In one embodiment, thetreated process fluid from the oil removal and flocculation module 441may be transferred to another module 441, for example, a solids removaland filtration module 551, by a transfer pump 453 for furtherprocessing.

In one embodiment, the oil removal and flocculation module 441 may becoupled to another module, for example a ventilation supply module 1110,that supplies ventilation supply air 468. In one embodiment, ventilationsupply air 468 may be supplied to the oil removal and flocculationmodule 441 at a rate of up 24 air changes or more per hour and may bedischarged from the module 441 through at least one louver 470, that maybe fixed or variable. In one embodiment, the coalescing tank 442 may beseparately vented to the outside in the event hydrogen sulfide isexported into the oil removal and flocculation module 441 through theprocess fluid. A dust extraction hood 471 and filter may be disposedabove the hopper 447 to extract residual dust resulting from theaddition of the flocculation chemicals to the hopper 447. In the eventof ESD, the ventilation supply air 468 to the oil removal andflocculation module 441 may be stopped by isolation dampeners 473coupled to conduit 472 through which the ventilation air 468 issupplied.

Solids Removal & Filtration Module

FIG. 6 shows one embodiment of a solids removal and filtration module551. In the embodiment shown, the solids removal and filtration module551 comprises a belt filter 553 coupled to a containment 550 forremoving solid material from a process fluid coupled to a storage tank554. In this embodiment, at one least filter canister may be coupled tothe storage tank 554. In one embodiment, a plurality of filter canistersmay be connected in series, wherein a first filter canister 556 iscoupled to the storage tank 554. While the solids removal and filtrationprocesses described herein are disposed in one module, the solidsremoval and filtration module 551, one of ordinary skill in the art willappreciate that these two processes may be disposed in separate modules,for example, the belt filter 554, containment 550, and storage tank 554may be disposed in one module, and the plurality of filter canisters maybe disposed in a second module, so long as each module is sufficientlysmall to be mobile and each module may be connected to another modulefor assembly on-site.

In one embodiment, a process fluid from another module, for example, theoil removal and flocculation module 441 (FIG. 5), may be pumped througha containment 550 coupled with a belt filter 553. In one embodiment, thebelt filter 553 comprises a conveyor 540 having a filter medium 559. Inone embodiment, the filter medium 559 may comprise polyester. One ofordinary skill in the art will appreciate, however, that a filter of anyof a number of materials may be used so long as it filters out solidmaterial from the process fluid. As the process fluid flows through thefilter medium 559, solid materials 557 are removed from the processfluid and retained on the filter medium 559. As process fluid continuesto flow through the filter medium 559, the solid materials retained onthe filter medium 559 increases and may blind or clog the filter medium559. Accordingly, the level of process fluid on the filter medium 559increases due to a blockage of flow. A predetermined level of processfluid on the filter medium 559 may trigger a forward motion (indicatedby arrow C) of the conveyor 540 and filter medium 559. In oneembodiment, a sensor 558 may detect the level of process fluid on thefilter medium 559. The filter medium 559 is conveyed out of thecontainment 550, removing the retained solid materials out of the solidmaterials removal and filtration module 551 for disposal 560. In oneembodiment, a hydrogen sulfide PLC 542 may control movement of theconveyor 540 and filter medium. In one embodiment, the hydrogen sulfidePLC 542 may move the conveyor 540 and filter medium 559 forward until apredetermined flow rate of process fluid through the filter medium 559is resumed, thereby reducing the fluid level on the filter medium 559.In one embodiment, a sensor 558 may detect the flow rate of the processfluid through the filter medium 559. In another embodiment, the sensor558 that detects the level of process fluid on the filter medium 559 maysignal the PLC 542 when the fluid level on the filter medium 559 hasbeen reduced to the predetermined flow rate of process fluid through thefilter medium 559.

The process fluid that flows through the filter medium 559 of the beltfilter 553 may then flow into a storage tank 554. Once the process fluidreaches a predetermined height in the storage tank 554, the processfluid may be transferred by a pump 562, for example, by a centrifugalpump, to at least one filter canister wherein solids particles andhydrocarbons may be removed from the process fluid. Each of the at leastone filter canister comprises a filter, for example a bag filter or acartridge filter. In one embodiment, the process fluid is pumped to afirst filter canister 556 of a series of three filter canisters, whereinthe first filter 556 canister is coupled to a second filter canister 563and the second filter 563 canister is coupled to a third filter canister564. In this embodiment, a plurality of bag filters 565 may be disposedinside the first filter canister 556 to remove solid particles from theprocess fluid.

In one embodiment, three bag filters may be disposed in the first filtercanister 556 that remove solid particles larger than about 20 micronsfrom the process fluid. The process fluid may then flow through thefirst filter canister 556 and into the second canister 563. A pluralityof filter cartridges 566 may be disposed inside the second filtercanister 563 for removal of solid particles from the process fluid. Inone embodiment, 28 filter cartridges may be disposed inside the secondfilter canister 563 that remove solid particles larger than about 10microns from the process fluid. The process fluid may then flow from thesecond filter canister 563 to the third filter canister 564. A pluralityof filter cartridges 566 may be disposed inside the third filtercanister 564 for removal of hydrocarbons from the process fluid.

In one embodiment, 28 filter cartridges may disposed in the third filtercanister 564 that remove hydrocarbon larger than about 10 microns. Oneof ordinary skill in the art will appreciate that the number of filtercanisters, the number of filters within a filter canister, and the sizeof the particles removed by each filter may vary without departing fromthe scope of the invention. In one embodiment, differential pressuretransducers 567 may be coupled to each filter canister to detectclogging of the filters. In this embodiment, the pressure transducer 567may signal an operator if the filters become plugged so that the filtersmay be cleaned or replaced. After the process fluid has flowed throughthe filter canisters, the process fluid may be transferred to anothermodule 568, for example a treated fluid storage module.

In one embodiment, the solids removal and filtration module 551 may becoupled to another module, for example a ventilation supply module 1110,that supplies ventilation supply air 569. In one embodiment, ventilationsupply air 569 may be supplied to the solids removal and filtrationmodule 551 at a rate of up to 24 air changes or more per hour and may bedischarged from the module 551 through at least one louver 570, that maybe fixed or variable. In the event of ESD, the ventilation supply air569 to the solids removal and filtration module 551 may be stopped byisolation dampeners 574 coupled to conduit 572 through which theventilation air 569 is supplied.

Treated Fluid Storage Module

FIG. 7 shows one embodiment of a treated fluid storage module 661. Thetreated fluid storage module 661 may be configured to receive a treatedprocess fluid from another module, for example, the solids removal andfiltration module 551. In this embodiment, the treated fluid storagemodule 661 comprises an oil-in-water monitoring system 663 for measuringthe concentration of oil within a treated process fluid entering thetreated fluid storage module 661 from another the solids removal andfiltration module 551. The treated fluid storage module 661 furthercomprises a tank 664 for storing the treated process fluid. In oneembodiment, a level sensor 665 may be disposed in the storage tank 664to measure the volume of fluid contained in the tank 664 and may signala PLC 666 to shut off the transfer pump 658 that transfers the processfluid into the treated fluid storage module 661 when a predeterminedvolume of fluid is contained in the tank 664.

In one embodiment, a treated process fluid may be transferred fromanother module, for example, the solids removal and filtration module551, into the treated fluid storage module 661. The treated processfluid may flow through an oil-in-water monitoring system 663, forexample, a Rivertrace Engineering oil-in-water monitor (Calgary,Alberta, Canada), disposed in the treated process fluid module 661 thatperforms an inspection of the treated process fluid. The oil-in-watermonitor 663 measures the content of oil within the treated processfluid. In one embodiment, treated process fluid having a concentrationless than a predetermined value of oil may be transported outside thesystem for safe disposal 656. Treated process fluid having aconcentration greater than the predetermined value of oil may betransported to tank 664 disposed in the treated fluid storage module 661for storage. In one embodiment, the predetermined value of oilconcentration in the process fluid is about 40 ppm. In one embodiment,the tank 664 may have a volume of approximately nine hundred cubic feet(about 26 m³). The treated process fluid contained in the tank 664 maybe stored for a predetermined amount of time. In one embodiment, theprocess fluid may be stored for thirty minutes. The treated processfluid contained in the tank 664, that is, treated process fluid havingmore than 40 ppm of oil, may be pumped from the tank to another modulefor further processing. In one embodiment, the treated process fluidcontained in the tank may be pumped back 667 to the degassing andneutralizing module 211 (FIG. 3) for further processing or tankcleaning. In another embodiment, the treated process fluid may be pumpedfrom the tank 664 back to the oil removal and flocculation module 441(FIG. 5) for further oil removal and flocculation.

In one embodiment, the treated fluid storage module 661 may furthercomprise at least one louver 668, that may be fixed or variable,disposed proximate a pump end of the treated fluid storage module 661for cooling a pump motor. The treated fluid storage module 661 may beunmanned and may operate in a Zone 1 area.

Local Electric Room Module

FIG. 8 shows one embodiment of a local electric room module 771. In theembodiment shown, the local electric room module 771 comprises aplurality of systems that may control different aspects of the connectedmodular system for treating a process fluid. In one embodiment, thelocal electric room module 771 may be electrically connected 40, 41(FIG. 1) to PLCs, pumps, valves, aeration devices, blowers, and otheradjustment mechanisms disposed in any one of the various modules. In oneembodiment, the local electric room module 771 may comprise a hydrogensulfide PLC system 773, a Fire and Gas detection and Emergency Shut Down(F&G/ESD) system 774, and a Motor Control Center (MCC) 775.

In one embodiment, a hydrogen sulfide PLC system 773 may be disposed inthe local electric room module 771 that operatively controls a pluralityof processes of the modular system for treating a process fluid. Forexample, the hydrogen sulfide PLC system 773 may be provided by CoralEngineering, The hydrogen sulfide PLC 773 system may interface with aplurality of field sensors, the MCC 775, and/or the F&G/ESD system 774.In one embodiment, an operator interface, or Human Machine Interface 882(HMI), may be located in a control room module 881, as described in moredetail below with reference to FIG. 9. The HMI 882 may allow an operatorto monitor and control the hydrogen sulfide PLC 773.

In one embodiment, a F&G/ESD system 774 may be disposed in the localelectric room module 771 and may shut down the modular system in a safemanner in the event a serious process condition, for example a fire orgas leak, occurs. For example, the F&G/ESD system 774 may be providedby, for example, ICS Triplex, In one embodiment, the F&G/ESD system 774may be rated as a Safety Integrity Level (SIL) 3. The F&G/ESD system mayinterface with a plurality of field sensors to determine the processconditions of the modular system. In one embodiment, signals from theF&G/ESD system may be displayed on the hydrogen sulfide PLC HMI 882 tofacilitate diagnostics of the modular system.

In one embodiment, a MCC 775 may be disposed in the local electric roommodule 771 and may control and monitor the motor power for the modularsystem. For example, the MCC 775 may be provided by, for example, AkerElektro. Starters in the MCC system may communicate with the hydrogensulfide PLC.

In one embodiment, ventilation for the local electric room module 771may be provided by air 762 drawn in from outside the module to maintainan overpressure within the module. Ventilation supply air 762 may besupplied to the local electric room module 771 at a rate of up to 6 airchanges or more per hour. The local electric room module 771 may beequipped with heating and air conditioning to maintain desiredventilation. A sensor 760 may be disposed in the local electric roommodule 771 that detects hydrogen sulfide and other gases in theventilation air 762. In the event the sensor detects hydrogen sulfide orgases in the ventilation air 762, the ventilation will shut down.Isolation dampeners 764 may seal the module from further gas intrusion.The local electric room module 771 may be certified for Zone 1 IIB T2operations.

Control Room Module

FIG. 9 shows one embodiment of a control room module 881. In theembodiment shown, the control room module 881 comprises an operator workstation and a system laboratory. In one embodiment, the control room maybe electrically connected 43 (FIG. 1) to at least one of the systems,including the hydrogen sulfide PLC system 773, the F&G/ESD system 774,and the MCC 775, disposed in the local electric room module 771. In oneembodiment, the control room module 881 may be disposed on top of thelocal electric room module 771 (FIG. 8).

In one embodiment, a hydrogen sulfide PLC HMI 882 may be disposed in thecontrol room module 881. The hydrogen sulfide PLC HMI 882 provides anoperator a graphical interface of the process in a process andinstrumentation diagram (P&ID) format. An example PLC HMI may beprovided by, for example, Coral Engineering.

Further, a hydrogen sulfide PLC server 884 may be disposed in thecontrol room module 881 that manages the modular system. In oneembodiment, the hydrogen sulfide PLC server 884 may be provided by, forexample, Coral Engineering. In one embodiment, the PLC server maycomprise a software system that facilitates management of the processesof the modular system. For example, the hydrogen sulfide PLC server maycomprise a supervisory control and data acquisition (SCADA) packagesystem that operates on Cimplicity®, Plant Edition.

In one embodiment, ventilation for the control room module 881 may beprovided by air 862 drawn in from outside the module to maintain anoverpressure within the module. In one embodiment, ventilation supplyair 862 may be supplied to the control room module 881 at a rate of upto 6 air changes or more per hour. The control room module 881 may beequipped with heating and air conditioning to maintain desiredventilation. A sensor 760 may be disposed in the control room module 881that detects hydrogen sulfide and other gases in the ventilation air862. In the event the sensor 760 detects hydrogen sulfide or gases inthe ventilation air 862, the ventilation will shut down. Isolationdampeners 864 may seal the module from further gas intrusion. Thecontrol room module 881 may be certified for Zone 1 IIB T2 operations.

Sulfide Treatment Module

FIG. 10 shows one embodiment of a sulfide treatment module 991. In theembodiment shown, the sulfide treatment module 991 comprises a systemfor removing hydrogen sulfide gas from ventilation air from, forexample, the mechanical degasser, the degassing compartment of thedegassing and neutralizing module, the neutralizing compartment of thedegassing and neutralizing module, and/or the process fluid storagemodule, herein collectively referred to as ‘sour gas’ 992. The sulfidetreatment module 991 comprises a tank 994 for containing a gas. In oneembodiment, the tank 994 may have an approximate volume of twelvehundred cubic feet (about 35 m³).

In one embodiment, the sulfide treatment module 991 comprises aconsumable medium 986 that chemically reacts with the sour gas 992,thereby reducing the amount of hydrogen sulfide in the sour gas 992. Inone embodiment, the consumable medium 986 capacity of the tank 994 isapproximately 20 ton. For example, a SulfaTreat® (M-I, L.L.C., Houston,Tex.) hydrogen sulfide treatment system may be disposed within thesulfide treatment module 991. In this embodiment, the hydrogen sulfidetreatment system process provides a chemical reaction that reduces thehydrogen sulfide in the sour gas 992 with a specifically designedconsumable medium 986. SulfaTreat® is a consumable medium that mayconvert hydrogen sulfide into a safe material for disposal whileallowing other gases to pass through. One of ordinary skill in the artwill appreciate that any material known in the art that reduces theamount of hydrogen sulfide in a gas stream may be used without departingfrom the scope of the invention.

In the embodiment shown in FIG. 10, sour gas 992 flows through aconsistently sized and shaped granular consumable medium 986 in afixed-bed or batch-type granular hydrogen sulfide reactant contained ina pressure vessel or tank 994. A potable water misting system 993 may beprovided within the module 991 to moisten the consumable medium 986 foroperation. As the sour gas 992 flows through the consumable medium 986,hydrogen sulfide reacts with the consumable medium 986 to form a stableand safe byproduct. Once the consumable medium 986 is at least partiallyconsumed, the misting system 993 may be used to cool the consumablemedium 986 for removal. In one embodiment, a gas, for example, methane,may result from the hydrogen sulfide treatment system process. Afterhydrogen sulfide has been removed from the sour gas 992, thehydrogen-sulfide-reduced gas may be extracted to the burner line module1020 and delivered to a burner line 1030 (FIG. 11) for flaring.

Burner Line Module

FIG. 11 shows one embodiment of a burner line module 1020. In theembodiment shown, the burner line module 1020 is provided to extractgases from the sulfide treatment module 991 and to deliver the gases toat least one burner 1030. In one embodiment the at least one burner 1030may be disposed at a location distant from the modular system. In oneembodiment, the at least one burner 1030 may be located as far as 425 ftaway.

In one embodiment, the burner line module 1020 comprises a hydrogensulfide gas detection system 1025, a particulate filter 1022, adetonation arrestor 1024, a rupture disc 1026, and a centrifugal blower1028 coupled to a motor 1027. The hydrogen sulfide gas detection system1025 may be installed in the burner line module 1020 to measure andmonitor the amount of hydrogen sulfide gas present in the gas stream.The hydrogen sulfide gas detection system 1025 may be coupled to F&G/ESDsystem so that, in the event the amount of hydrogen sulfide gas presentin the gas stream is above a pre-determined value, the hydrogen gasdetection system 1025 may shut down the burner line module. Thedetonation arrestor may 1024 be installed in the burner line module 1020with temperature sensors and an ESD valve to shut down the modularsystem in the event a flame travels up the burner line 1032. In theevent the detonation arrestor 1024 becomes plugged and an overpressuresituation arises in the sulfide treatment module 991, a rupture disc1026 allows this system, or burner line module 1120, to be bypassed andgas flow from the sulfide treatment module 991 may be sent directly to aburner 1030.

In one embodiment, the blower and motor may be enclosed to limit noiseoutput. The burner line module 1020 may be covered, but open on thesides to ventilate the burner line module 1020.

Ventilation Supply Module

FIG. 12 shows one embodiment of a ventilation supply module 1110 thatsupplies ventilation to any one of the other modules in the modularsystem. In one embodiments, the ventilation supply module comprisesisolation dampeners 1124, an air heater 1112, a coalescing filter 1114,and at least one blower 1116.

In one embodiment, ventilation supply air 1103 may be ducted in fromoutside the module. In one embodiment, the ventilation supply air 1103may be ducted 1118 from an elevation above the control room module 881(FIG. 9). For example, the ventilation supply air 1103 may be ductedfrom a approximately 30 feet above the ground. The ventilation supplyair 1103 may then pass through the air heater 1112 and a coalescingfilter 1114, thereafter forming two separate air supply systems. A firstair system 1120 may deliver supply air via insulated ducting to thedegassing and neutralizing module 211 (FIG. 3) and the process fluidstorage module 331 (FIG. 4). A second air system 1122 may deliver supplyair via ducting to the oil removal and flocculation module 441 (FIG. 4)and the solids removal and filtration module 551 (FIG. 6). Each airsystem has an axial blower 1116 to power the ventilation supply air. Inthe event of an ESD, isolation dampeners 1124 will close preventing airsupply from entering other process modules.

In one embodiment, the ventilation supply module may comprise a cover orlid, however, may be open on the sides allowing ventilation of theventilation supply module.

Piping Suitcase

In one embodiment, a piping suitcase 28, shown in FIG. 1, may beprovided that allows easy connection of piping for the system utilitiesand module interconnection. In one embodiment, the piping suitcase 28may include a plurality of pipes, connections, and inline processequipment that allows a module to be coupled to another module bycoupling each module to the piping suitcase 28. For example, as shown inFIG. 1, the treated fluid storage module 661 and the degassing andneutralizing module 211 may be coupled to the piping suitcase 28,allowing fluid communication between the two modules 661, 211 shown at34. One of ordinary skill in the art will appreciate that the pipingsuitcase may be configured to couple any of the modules together.Additionally, one of ordinary skill in the art will appreciate that thepiping suitcase may be configured to couple a module with a plurality ofmodules.

Materials

Tanks disposed in any one of the modules above that may be exposed tocorrosive process fluids may be constructed of any material known inthat art that will withstand corrosive process fluids. In oneembodiment, the tanks exposed to corrosive process fluids may beconstructed of stainless steel, for example, grade 316L SS. Inlineprocess equipment, sensors, valves, piping, flanges, etc. that may beexposed to corrosive process fluids may also be constructed of stainlesssteel, for example grade 316L SS. Elastomeric materials for hoses andseals may be selected so as to be chemical and hydrocarbon resistant.

Embodiments of the invention may include one or more of the followingadvantages. Embodiments of the invention provide a process fluidtreatment system that comprises various modules sized so that they aresufficiently small to mobile. Embodiments of the invention provide amodular system that may be assembled on-site for the treatment ofprocess fluids. Embodiments of the invention provide a method fortreating process fluids to reduce the amount of contaminants from theprocess fluid, including solids, gases, such as hydrogen sulfide, andoil.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

1. A system for treating a process fluid comprising a modulararrangement, the modular arrangement comprising: a first module thatreduces the amount of dissolved and entrained hydrogen sulfide gas inthe process fluid and monitors the pH of the process fluid; a secondmodule in fluid communication with the first module that stores theprocess fluid if an amount of hydrogen sulfide gas entrained in theprocess fluid is above a pre-selected value; a third module in fluidcommunication with the second module that reduces an amount of oil fromthe process fluid and flocculates the process fluid; a fourth module influid communication with the third module that reduces the amount ofsolids from the process fluid; a fifth module in fluid communicationwith the fourth module that measures the amount of oil in the processfluid and stores treated process fluid; a sixth module in fluidcommunication with at least one of the first module, the second module,the third module, and the fourth module that provides ventilation supplyair; a seventh module in fluid communication with the first module andthe second module that removes hydrogen sulfide gas from a sour gas; aneighth module in fluid communication with the seventh module thatdelivers gases to a burner system; a ninth module in communication withthe first through eighth modules of the system that controls theprocesses of the system; and a tenth module in communication with theninth module comprising a work station and system laboratory.
 2. Thesystem of claim 1, wherein the size of each module is sufficiently smallto be mobile and wherein the system is assembled onsite by connectingthe mobile modules together.
 3. The system of claim 1, furthercomprising an eleventh module having a tank for reducing the amount ofgas and solids in the process fluid.
 4. The system of claim 3, whereinthe tank comprises a cyclone separator.
 5. The system of claim 3,wherein the tank in the eleventh module comprises separation baffles anda weir arrangement.
 6. The system of claim 1, wherein the third moduleis configured to receive the process fluid if the amount of hydrogensulfide gas entrained in the process fluid is below a pre-selectedvalue.
 7. The system of claim 1, wherein the first module comprises atank having a degassing compartment, a neutralizing compartment, and aweir arrangement.
 8. The system of claim 7, wherein the degassingcompartment comprises a mechanical degasser and an aeration device. 9.The system of claim 7, wherein the neutralizing compartment comprises apH analyzer and a pump that supplies at least one chemical for adjustingthe pH of the well fluid.
 10. The system of claim 1, wherein the secondmodule comprises a process fluid storage tank.
 11. The system of claim1, wherein the third module comprises a coalescing tank and aflocculation tank.
 12. The system of claim 11, wherein the coalescingtank comprises three compartments, wherein a coalescing filter and acoalescing oil trap are disposed between a first compartment and asecond compartment and a weir arrangement is disposed between the secondcompartment and a third compartment.
 13. The system of claim 1, whereinthe fourth module comprises a belt filter coupled to a storage tank. 14.The system of claim 13, further comprising at least one filter canistercoupled to the storage tank.
 15. The system of claim 14, wherein each ofthe filter canisters is coupled to a differential pressure transducerfor detecting clogging of the filters.
 16. The system of claim 1,wherein the fifth module comprises a monitoring system that measures theconcentration of oil with the treated process fluid and a tank forstoring the treated process fluid.
 17. The system of claim 1, whereinthe seventh module comprises a tank provided with a consumable mediumdisposed therein and configured to receive a sour gas.
 18. The system ofclaim 17, further comprising a water misting system.
 19. The system ofclaim 1, wherein the eighth module comprises a hydrogen sulfide gasdetection system, a particulate filter, a detonation arrestor, a rupturedisc, and a blower coupled to a motor.
 20. The system of claim 1,wherein the sixth module comprises isolation dampeners, an air heater, acoalescing filter, and at least one blower.
 21. The system of claim 1,wherein the ninth module comprises a hydrogen sulfide programmable logiccontroller system, a fire and gas detection and emergency shut downsystem, and a motor control center.
 22. The system of claim 21, whereinthe hydrogen sulfide programmable logic controller system operativelycontrols a plurality of processes of the system.
 23. The system of claim21, wherein the fire and gas detection and emergency shut down systeminterfaces with a plurality of sensors and shuts down the system if aserious process condition occurs.
 24. The system of claim 1, wherein thetenth module comprises a hydrogen sulfide programmable logic controllerhuman machine interface and a hydrogen sulfide programmable logiccontroller server.
 25. The system of claim 1, further comprising apiping suitcase that allows easy connection of piping for the systemutilities and module interconnection.